This section is intended to introduce various aspects of the art, which may be associated with embodiments of the disclosed techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the disclosed techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Faults in sandstone-shale sequences have the potential to diminish cross-fault gas, oil and water flow by diminishing the cross-sectional reservoir area available for flow and by introducing a layer of low permeability fault zone materials distributed along a fault. When fault juxtaposition areas are small and fault zone materials distributed across the area of reservoir contact have low permeability, faults have the potential to create a really limited compartments of gas and oil that diminish the productive capacity of wells.
Fault zone materials develop low permeability through the fault processes of cataclasis, shale smear and cementation. Cataclasis operates on the porous and permeable part of the stratigraphy (sandstone) by breaking, fragmenting, and crushing detrital sand grains, reducing the mean size of grains and, importantly, the size of pores between the grains. In some instances, the permeability effects of cataclasis are augmented by cementation and annealing of the broken fragments, further reducing pore sizes. Shale smear, on the other hand, decreases the permeability of the aggregate fault zone by introducing the low permeability component of the stratigraphy (shale).
With respect to predicting fluid flow in a subsurface region, the current practice is to evaluate the effects of fault zone materials on cross-fault flow by calculating some variation on a Shale Gouge Ratio (SGR) or Clay Smear Potential (CSP). These measures both represent properties that are essentially proportional to the shale fraction of the sedimentary section faulted past every point along the fault. SGR and CSP values are converted to gouge or gauge permeability based on empirically defined log-linear relations between SGR and CSP and measured permeability from faults sampled in cores or outcrops.
The current practice is limited in two respects: predictive capability and robustness. With respect to predictive capability, most approaches require local calibration of SGR to fault permeability, limiting utility of the approach early in development when estimates of reservoir compartmentalization are most acute. With respect to robustness, known practices fail to account for the absence of the impact of fault zone materials on cross-fault flow in some settings where the volume of sand (net) is relatively small compared to the total rock volume (gross) (low net:gross (N:G) sections). Known practices also fail to take into consideration the apparent low permeability of faults in some high N:G sections. An improved method of evaluating the impact of the presence and composition of fault zone materials on reservoir fluid flow is desirable.